Fracturing fluids and methods for treating hydrocarbon-bearing formations

ABSTRACT

Disclosed herein is a fracturing fluid comprising a carrier fluid; a polymer that is soluble in the carrier fluid; the polymer being a synthetic polymer, wherein the synthetic polymer comprises a labile group that is operative to facilitate decomposition of the synthetic polymer upon activation of the labile group; the synthetic polymer being operative to increase the viscosity of the carrier fluid to about 5 to about 50 centipoise; the fracturing fluid being operative to reduce friction during a downhole fracturing operation and to transport a proppant during the downhole fracturing operation; and an oxidizing agent. A method for treating a hydrocarbon-bearing formation is also disclosed herein.

CROSS-REFERENCE TO RELATED ART

This application claims priority to U.S. application Ser. No.13/537,800, which was filed with the U.S. Patent and Trademark Office onJun. 29, 2012, the entire contents of which are hereby incorporated byreference.

BACKGROUND

Hydraulic fracturing increases fluid (e.g., hydrocarbons, and the like)flow from a subterranean zone by creating new fractures and facilitatingconnectivity of the existing pores and natural channels contained in thesubterranean zone. Hydraulic fracturing is a process by which cracks orfractures in the subterranean zone are created by pumping a fracturingfluid at a pressure that exceeds the parting pressure of the rock. Thefracturing fluid creates or enlarges fractures in the subterranean zoneand a particulate proppant material suspended in the fracturing fluidmay be pumped into the created fracture. This process is also known as“frac-packing”. The created fracture continues to grow as more fluid andproppant are introduced into the formation.

The proppants remain in the fractures in the form of a permeable “pack”that serves to hold open or “prop” the fractures open. After placementof the proppant materials, the fracturing fluid may be “broken” andrecovered by using a breaker or a delayed breaker system to facilitate areduction in the viscosity of the fracturing fluid. The reduction influid viscosity along with fluid leak-off from the created fracture intopermeable areas of the formation allows for the fracture to close on theproppants following the treatment. By maintaining the fracture open, theproppants provide a highly conductive pathway for hydrocarbons and/orother formation fluids to flow into the borehole.

Slickwater fracturing is a type of treatment used in the stimulation ofunconventional formations. Due to extremely low formation permeability,fluid leak-off is normally not of concern. During the slickwaterhydraulic fracturing process, the pumping rate is generally very high tohelp facilitate the transport of proppants into the formation inconjunction with the use of the low viscosity fluid. At such fluidvelocities the proppants in the fracturing fluids can be very abrasive,leading to reduced service life for fracturing equipment. In addition,friction between various components of the fracturing equipment canproduce wear of the equipment. It is therefore desirable to reduce thewear on the equipment during fracturing. Guar is often used to increasethe viscosity in fracturing fluids to reduce the amount of wear. Largeamounts of guar in the form of a linear gel (non-crosslinked) areemployed for this purpose.

A significant proportion of the total guar used in fracturing fluidoperations is in the form of crosslinked fracturing fluids. For oilformations, in order to obtain the desired fracture width, higherviscosity fracturing fluids are employed. Consequently, higher loadingof proppants are used to suitably prop open the relatively widefractures. Fluids with low viscosity typically lack sufficient viscosityto carry such amounts of proppants, especially at high temperatures. Dueto the costs associated with guar, it is not economical to obtain thedesired high viscosity by simply increasing the concentration of theguar polymer. Overly concentrated guar fracturing fluids lead to adverseeffects for the formation and proppant pack, i.e., formation or proppantpack damage, offsetting the benefit brought by the fracturing process.Thus, crosslinkers are widely used to promote crosslinking of the guaror guar-derived polymer by forming a three-dimensional (3D) network. Thecrosslinking agent increases the viscosity of the fracturing fluid suchthat the fracturing fluid has sufficient strength and viscosity tocreate or enlarge fractures and/or to carry the proppants during thecourse of the fracturing process, even at elevated temperatures. Therecovery of the fracturing fluid is accomplished by using a breaker or adelayed breaker system to “break” the crosslinked guar polymers andreduce the viscosity of the fracturing fluid.

As a naturally occurring material, guar is a limited natural resource,the demand for which has increased greatly in recent years. In additionto significant supply limitations, guar-based fracturing fluids are alsolimited by other significant disadvantages, including but not limitedto, the hydration limitations of the guar polymer, formation damage,i.e., undesirable coating of proppant materials and/or formationsurfaces with the guar polymer or residue, and instability of the guarpolymer at elevated temperatures in certain types of fracturingapplications.

It is therefore desirable to provide an alternative to guar-basedfracturing fluids, which solves one or more of the above problemsassociated with these guar-based fracturing fluids. It is also desirableto provide an alternative to guar-based fracturing fluids whereby thedecomposition or the breaking of labile linkages therein can befacilitated, thereby lowering the viscosity and allowing for removal ofthe fracturing fluid.

SUMMARY OF THE DISCLOSURE

Disclosed herein is a fracturing fluid comprising a carrier fluid; apolymer that is soluble in the carrier fluid; the polymer being asynthetic polymer, wherein the synthetic polymer comprises a labilegroup that is operative to facilitate decomposition of the syntheticpolymer upon activation of the labile group; the synthetic polymer beingoperative to increase the viscosity of the carrier fluid to about 5 toabout 50 centipoise at 300 s′; the fracturing fluid being operative toreduce friction during a downhole fracturing operation and to transporta proppant during the downhole fracturing operation; and an oxidizingagent.

Disclosed herein too is a method for treating a hydrocarbon-bearingformation comprising blending a carrier fluid with a polymer to form afracturing fluid, the fracturing fluid having a viscosity of about 5 toabout 50 centipoise at 300 s⁻¹; the polymer being a synthetic polymer;discharging the fracturing fluid into a downhole fracture in thehydrocarbon-bearing formation, wherein the fracturing fluid is operativeto reduce friction during a hydrocarbon-bearing treatment operation; andadding an oxidizing agent to the fracturing fluid.

BRIEF DESCRIPTION OF THE DRAWINGS

For a detailed understanding of the present disclosure, referencesshould be made to the following detailed description, taken inconjunction with the accompanying drawings in which like elements havegenerally been designated with like numerals and wherein:

FIG. 1 is a graph depicting the dynamic hydration viscosity versus timefor a) guar and b) the synthetic polymer at different concentrations inwater;

FIG. 2 is a graph depicting the dynamic hydration viscosity attemperatures of 45° F. and 80° F. versus time for the synthetic polymerin water;

FIG. 3 is a graph depicting the effective permeability of a simulatedfracture surface when contacted with a fracturing fluid that containsthe synthetic polymer;

FIG. 4 is a graph depicting the effective permeability of a simulatedfracture surface when contacted with a comparative fracturing fluid thatcontains the guar;

FIG. 5 is a graph depicting the apparent viscosity versus time andtemperature for a fracturing fluid that contains the synthetic polymerand an oxidizing agent;

FIG. 6 is a graph depicting the apparent viscosity versus time andtemperature for a fracturing fluid that contains the synthetic polymer,an oxidizing agent and a reducing agent; and

FIG. 7 is a graph depicting the apparent viscosity versus time andtemperature for fracturing fluids that contain the synthetic polymer, anoxidizing agent, a reducing agent, a carrier fluid, a clay control agentand crosslinking agents.

DESCRIPTION OF EMBODIMENTS

Slickwater fracturing is a type of treatment used in the stimulation ofunconventional formations. Due to extremely low formation permeability,fluid leak-off is normally not of concern, and therefore low viscosityfluids can be used for slickwater fracturing. During the slickwaterfracturing process, the pumping rate is generally very high to helpprevent settlement of the proppants in the fluid. When pumping at such ahigh rate or velocity, there is a high frictional pressure generatedduring the fluid flow in the surface pipes as well as inside theborehole. A high molecular weight synthetic polymer is added to theslickwater fracturing fluid as a friction reducer to reduce such fluidflow friction. The concentration of the synthetic polymer frictionreducer is controlled such that the fluid viscosity is less than 2centipoise (cP). Higher concentrations of the friction reducing polymerlead to a fluid viscosity of higher than 3 centipoise, often resultingin increased friction, which defies the purpose of using a frictionreducer in slickwater fracturing applications. At such fluid velocitiesthe proppants in the fracturing fluids can be very abrasive, leading toreduced service life for fracturing equipment. In addition, frictionbetween various components of the fracturing equipment can produce wearof the equipment. Increasing the viscosity of the fracturing fluid bythe addition of a polymer, even at relatively low viscosities, helps tomake it possible to pump the fracturing fluid with reduced proppantsettling and thus to lessen this abrasive effect and consequently toreduce friction and equipment wear.

Disclosed herein is a fracturing fluid that comprises a polymer and acarrier fluid. In one embodiment, the polymer is a synthetic polymer(i.e., it is a man-made polymer) and can rapidly dissolve, or hydrate,in the carrier fluid thereby increasing the viscosity of the carrierfluid so as to reduce friction between the various components offracturing equipment used in the hydraulic fracturing process.

In an exemplary embodiment, the fracturing fluid reduces frictionbetween components of the fracturing equipment during an early stage aswell as during subsequent stages of dissolution of the polymer in thecarrier fluid. It also prevents the proppants from settling out of thefracturing fluid (phase separating) during subsequent stages ofdissolution of the polymer in the carrier fluid. The ability of thepolymer to rapidly dissolve into the carrier fluid minimizes the use ofpre-dissolution procedures and hydration equipment, thus reducingcapital costs and maintenance costs. This rapid dissolution ability alsopermits the carrier fluid to transport proppants downhole whilepermitting them to remain slurried in the carrier fluid (i.e., withreduced settling or falling out of solution) while it is beingtransported to the fracture. In an exemplary embodiment, the fracturingfluid reaches its maximum viscosity within 10 to 40 seconds afterintroduction of the polymer into the carrier fluid, which allows slowersettling of proppant within the fluids at lower pumping rate, andpermits to reduce friction between the various components of thefracturing equipment.

The polymer is soluble in a carrier fluid, for example, an aqueousmedium such as water or slickwater to form the fracturing fluid. In anexemplary embodiment, the polymer is an organic water-soluble syntheticpolymer (i.e., it is a polymer that is man-made). In addition to thesynthetic polymer, the polymer may comprise a naturally occurringpolymer. A “naturally occurring” polymer is one that is derived from aliving being such as an animal, a plant, a microorganism, or the like.The polymer can therefore comprise a naturally occurring polymer so longas it is blended with or copolymerized with the synthetic polymer.

In one embodiment, the polymer also comprises a labile group that can bedecomposed upon activation. The decomposition of the labile grouppermits a reduction in the viscosity of the fracturing fluid and alsopermits its removal from the fracture after a conductive path isestablished through the proppants in the fracture. The conductive pathpermits the extraction of hydrocarbons from the fracture.

The polymer can comprise a blend of polymers, a copolymer, a terpolymer,an oligomer, a homopolymer, a block copolymer, an alternating blockcopolymer, a random copolymer, a random block copolymer, a graftcopolymer, a star block copolymer, a dendrimer, an ionomer, anelastomer, a polyelectrolyte, or the like, or a combination comprisingat least one of the foregoing polymers.

In one embodiment, the polymer may be a linear polymer, a branchedpolymer or a crosslinked polymer. In another embodiment, the polymer cancomprise a blend of two or more synthetic polymers or a copolymer of twoor more synthetic polymers. For example, the polymer can comprise afirst synthetic polymer and a second synthetic polymer that are blendedtogether or are that are copolymerized together. The copolymerizationmay involve covalent bonding and/or ionic bonding. In one embodiment,the first synthetic polymer is hydrophilic, while the second syntheticpolymer is hydrophobic. In yet another embodiment, the polymer maycomprise a copolymer of a synthetic polymer and a naturally occurringpolymer, where the naturally occurring polymer can be either hydrophilicor hydrophobic.

In one embodiment, the polymer is a water soluble polymer. Examples ofthe water soluble polymer are polyacrylates, polyacrylamides,polyvinylacetates, polyvinyl acetamides, polyvinyl alcohols, neutralizedand un-neutralized polymeric acids (e.g., neutralized and un-neutralizedpolyacrylics acids, neutralized and un-neutralized polysulfonic acids,neutralized and un-neutralized polystyrene sulfonic acids, or the like)polydiallyl dimethyl ammonium chlorides, poly(1-glycerol methacrylate)s,poly(2-dimethylaminoethyl methacrylate)s, poly(2-ethyl-2-oxazoline),poly(2-hydroxyethyl methacrylate/methacrylic acid)s,poly(2-hydroxypropyl methacrylate)s,poly(2-methacryloxyethyltrimethylammonium halide)s,poly(2-vinyl-1-methylpyridinium halide)s, poly(2-vinylpyridineN-oxide)s, poly(2-vinylpyridine)s,poly(3-chloro-2-hydroxypropyl-2-methacryloxyethyldimethylammoniumchloride)s, or the like, or a combination comprising at least one of theforegoing water soluble polymers.

In one embodiment, the polymer can comprise one or more of the foregoingwater soluble polymers and a synthetic polymer that is hydrophobic solong as the resulting polymer is soluble in the carrier fluid. In anexemplary embodiment, the polymer can comprise one or more of theforegoing water soluble polymers and a synthetic polymer that ishydrophobic so long as the resulting polymer is soluble in an aqueouscarrier fluid. The foregoing water soluble polymers can be copolymerizedor blended with the hydrophobic synthetic polymer.

Examples of hydrophobic synthetic polymers are polyacetals, polyolefins,polycarbonates, polystyrenes, polyesters, polyamides, polyamideimides,polyarylates, polyarylsulfones, polyethersulfones, polyphenylenesulfides, polyvinyl chlorides, polysulfones, polyimides,polyetherimides, polytetrafluoroethylenes, polyetherketones, polyetheretherketones, polyether ketone ketones, polybenzoxazoles,polyphthalides, polyacetals, polyanhydrides, polyvinyl ethers, polyvinylthioethers, polyvinyl ketones, polyvinyl halides, polyvinyl nitriles,polyvinyl esters, polysulfonates, polysulfides, polythioesters,polysulfones, polysulfonamides, polyureas, polyphosphazenes,polysilazanes, polyethylene terephthalate, polybutylene terephthalate,polyurethane, polytetrafluoroethylene, polychlorotrifluoroethylene,polyvinylidene fluoride, polyoxadiazoles,polybenzothiazinophenothiazines, polybenzothiazoles,polypyrazinoquinoxalines, polypyromellitimides, polyquinoxalines,polybenzimidazoles, polyoxindoles, polyoxoisoindolines,polydioxoisoindolines, polytriazines, polypyridazines, polypiperazines,polypyridines, polypiperidines, polytriazoles, polypyrazoles,polypyrrolidines, polycarboranes, polyoxabicyclononanes,polydibenzofurans, polyphtalides, polyacetals, polyanhydrides, polyvinylethers, polyvinyl thioethers, polyvinyl ketones, polyvinyl halides,polyvinyl nitriles, polyvinyl esters, polysulfonates, polysulfides,polythioesters, polysulfones, polysulfonamides, polyureas,polyphosphazenes, polysilazanes, polysiloxanes, polyolefins, or thelike, or a combination comprising at least one of the foregoinghydrophobic synthetic polymers.

As noted above, the polymer can comprise a blend or a copolymer of asynthetic polymer and a naturally occurring polymer. Examples ofnaturally occurring polymers include polysaccharides, derivatives ofpolysaccharides (e.g., hydroxyethyl guar (HEG), carboxymethyl guar(CMG), carboxyethyl guar (CEG), carboxymethyl hydroxypropyl guar(CMHPG), cellulose, cellulose derivatives (i.e., derivatives ofcellulose such as hydroxyethylcellulose (HEC), hydroxypropylcellulose(HPC), carboxymethylcellulose (CMC), carboxyethylcellulose (CEC),carboxymethyl hydroxyethyl cellulose (CMHEC), carboxymethylhydroxypropyl cellulose (CMHPC)), karaya, locust bean, pectin,tragacanth, acacia, carrageenan, alginates (e.g., salts of alginate,propylene glycol alginate, and the like), agar, gellan, xanthan,scleroglucan, or the like, or a combination comprising at least one ofthe foregoing.

The polymer comprises a labile group that is operative to facilitatedecomposition of the polymer upon activation of the labile group. It isdesirable for the labile group to be water soluble or otherwise solublein the carrier fluid. Labile groups include ester groups, amide groups,carbonate groups, azo groups, disulfide groups, orthoester groups,acetal groups, etherester groups, ether groups, silyl groups,phosphazine groups, urethane groups, esteramide groups, etheramidegroups, anhydride groups, and any derivative or combination thereof. Insome embodiments, the labile links are derived from oligomeric or shortchain molecules that include poly(anhydrides), poly(orthoesters),orthoesters, poly(lactic acids), poly(glycolic acids),poly(caprolactones), poly(hydroxybutyrates), polyphosphazenes,poly(carbonates), polyacetals, polyetheresters, polyesteramides,polycyanoacrylates, polyurethanes, polyacrylates, or the like, or acombination comprising at least one of the foregoing oligomeric or shortchain molecules. In some embodiments, the labile links may be derivedfrom a hydrophilic polymeric block comprising at least one compoundselected from the group consisting of: a poly(alkylene glycol), apoly(alcohol) made by the hydrolysis of polyvinyl acetate), poly(vinylpyrrolidone), a polysaccharide, a chitin, a chitosan, a protein, apoly(amino acid), a poly(alkylene oxide), a poly(amide), a poly(acid), apolyol, any derivative, copolymer, or combination thereof.

The polymer can be manufactured via emulsion (or inverse emulsion)polymerization to obtain high molecular weights. In emulsionpolymerization or inverse emulsion polymerization, the polymers aresuspended in a fluid. In one embodiment, the fluid in which the polymeris suspended is water. The manufacturing and use of the polymer inemulsion form makes it possible to be used as a liquid additive therebysimplifying it use in the fracturing fluid.

Depending on the particular labile group, the polymer can be degraded byoxidation, reduction, photo-decomposition, thermal decomposition,hydrolysis, chemical decomposition or microbial decomposition. The ratesat which the polymer degrades is dependent on at least the type oflabile group, composition, sequence, length, molecular geometry,molecular weight, stereochemistry, hydrophilicity, hydrophobicity,additives and environmental conditions such as temperature, presence ofmoisture, oxygen, microorganisms, enzymes, pH, and the like.

The synthetic polymer has a number average molecular weight of about2,000,000 to about 20,000,000 specifically about 10,000,000 to about18,000,000 grams per mole.

In an exemplary embodiment, the polymer (used in the fracturing fluid)is a linear synthetic polymer and comprises a polyacrylamide.Commercially available synthetic polymers are MaxPerm-20® andMaxPerm-20A® from Baker Hughes, Incorporated.

In an embodiment, the polymer is employed in an amount of about 0.01 toabout 20 percent by weight (hereinafter “wt %”), specifically about 0.1to about 10 wt %, and more specifically about 0.05 to about 5 wt %,based on the total weight of the fracturing fluid.

In one embodiment, it is desirable for the polymer to be soluble in anaqueous carrier fluid. When the polymer comprises a hydrophobic and ahydrophilic portion, it is desirable for the polymer to have an overallstructure that lends itself to solubilization in an aqueous carrierfluid. In order to accomplish this, it is desirable for the polymer tohave a solubility parameter that is proximate to that of the carrierfluid so that the polymer can rapidly dissolve in the carrier fluid.

The selection of the chemical constituents of the polymer used in agiven fracturing application is determined, in part, using thesolubility parameter of the chemical constituents. The Hildebrandsolubility parameter is a numerical parameter, which indicates therelative solvency behavior of a polymer or a combination of polymers ina specific solvent. Here, the solvent is the carrier fluid. Thesolubility parameter is derived from the cohesive energy density of thepolymer. From the heat of vaporization in calories per cubic centimeterof liquid, the cohesive energy density (c) can be derived by thefollowing equation (1):

$\begin{matrix}{c = \frac{{\Delta\; H} - {RT}}{V_{m}}} & (1)\end{matrix}$where c=cohesive energy density; ΔH=heat of vaporization, R=gasconstant, T=temperature; and V_(m)=molar volume. In general terms, whentwo materials having similar cohesive energy density values, thesolubility parameter values are proximate to each other, since thesolubility parameter is the square root of the cohesive energy density.Two materials are considered to be miscible with one another when theyhave similar solubility parameters. By tailoring the polymer structure(i.e., by combining the appropriate amount of a hydrophillic polymerwith a hydrophobic polymer) the solubility parameter of the polymer canbe tailored to be proximate to that of a particular carrier fluid.

In metric units, the solubility parameter (δ) can be calculated incalories per cubic centimeter in metric units (cal^(1/2)cm^(−3/2)). InSI units, the solubility parameter is expressed is megapascals(MPa^(1/2)). The conversion of the solubility parameter from SI units tometric units is given by the equation (2):δ (MPa^(1/2))=2.0455×δ (cal^(1/2)cm^(−3/2))  (2)

The solubility parameter can be used to predict the solvency of aparticular combination of polymers (i.e., copolymers or blends ofpolymers) in a solvent. A solvent will generally swell the polymer whenthe solubility parameter is proximate to that of the polymer. Thesolubility parameter of the polymer can be calculated based on therelative weight fractions of each constituent of the polymer accordingto equation (3):δ_(polymer) =w ₁δ₁ +w ₂δ₂  (3)where δ_(polymer) is the solubility parameter of the copolymer or blendof polymers, δ₁ is the solubility parameter the hydrophilic polymer, w₁is the weight fraction of the hydrophilic polymer, δ₂ is the solubilityparameter of the hydrophobic polymer and w₂ is the weigh fraction of thehydrophobic polymer. In one embodiment, the solubility parameter of thecarrier fluid can be tailored to be proximate to that of the combinationof polymers if so desired.

In an embodiment, the solubility parameter of the polymer is withinabout 25% of the solubility parameter of the carrier fluid. In anotherembodiment, the solubility parameter of the synthetic polymer is withinabout 20% of the solubility parameter of the carrier fluid.

The carrier fluid solvates the polymer and in addition transports theproppant materials downhole to the hydrocarbon bearing formation. Thecarrier fluid is a liquid carrier that is generally suitable for use inhydrocarbon (i.e., oil and gas) producing wells. In an embodiment, thecarrier fluid is an aqueous solution. In another embodiment, the carrierfluid may be slickwater. Slickwater, for example, has a viscosity ofless than 3 centipoise. Water is generally a major component by totalweight of the carrier fluid. The water is potable, i.e., drinkable, ornon-potable. In an embodiment, the water is brackish or contains othermaterials that may be present in water found in or near oil fields. Inanother embodiment, the carrier fluid comprises a salt such as an alkalimetal or alkali earth metal salt (e.g., NaCO₃, NaCl, KCl, CaCl₂, and thelike) in an amount of from about 0.1 wt % to about 10 wt %, based on thetotal weight of the carrier fluid. In still yet another embodiment, thecarrier fluid is recycled fracturing fluid water or its residue.

In an embodiment, the fracturing fluid is a slurry, a gel, an emulsionor foam, e.g., hydrogel. As used herein, the term “emulsion” refers to amixture of two or more normally immiscible liquids which results in atwo-phase colloidal system wherein a liquid dispersed phase is dispersedin a liquid continuous phase. In an embodiment, the fracturing fluid isan oil-in-water emulsion. As used herein, the term “slurry” refers to athick suspension of solids in a liquid. As used herein, the term “gel”refers to a solid, jelly-like material. In one embodiment, gels aremostly liquid. Their solid-like behavior is the result of the formationof a three-dimensional crosslinked network within the liquid wherein theliquid molecules are dispersed in a discontinuous phase within a solidcontinuous phase. In one embodiment, the fracturing fluid is a slurry ora gelled slurry.

The fracturing fluid generally comprises the carrier fluid in an amountof about 95 to about 99.9 wt %, based upon the total weight of thefracturing fluid. In an exemplary embodiment, the fracturing fluidcomprises the carrier fluid in an amount of about 99 to about 99.5 wt %,based upon the total weight of the fracturing fluid.

In an embodiment, the fracturing fluid further comprises a proppant,i.e., proppant materials or particulate materials, which is carried intothe hydrocarbon formation by the fracturing fluid and remain in thefracture created, thus propping open the fracture when the fracturingpressure is released and the well is put into production. Examples ofproppant materials include sand, resin coated sands, plastic or plasticcomposite such as a thermoplastic or thermosetting composite or a resinor an aggregate containing a binder, walnut shells, sintered bauxite,glass beads, ceramic materials, synthetic organic particles such as, forexample, nylon pellets, naturally occurring materials, or the like, or acombination comprising at least one of the foregoing proppant materials.Suitable proppants further include those set forth in U.S. PatentPublication No. 2007/0209794 and U.S. Patent Publication No.2007/0209795, herein incorporated by reference.

The fracturing fluid generally comprises the proppant in an amount ofabout 1% to about 60 wt %, specifically about 1% to about 40 wt %, basedupon the total weight of the fracturing fluid.

As noted above, the polymer may be crosslinkable. In an embodiment, thepolymer is crosslinked during a fracturing operation. In anotherembodiment, the polymer is a co-polymer with cross-linkable monomers.Crosslinking the fracturing fluid further increases the viscosity of thecarrier fluid, traps proppant materials and prevents settling ofproppant materials.

Any suitable crosslinking agent is used to crosslink the polymer.Non-limiting examples of crosslinking agents include crosslinking agentscomprising a metal such as boron, titanium, zirconium, calcium,magnesium, iron, chromium and/or aluminum, as well as organometalliccompounds, complexes, ions or salts thereof, or a combination comprisingat least one of the foregoing. Non-limiting examples of suchmetal-containing crosslinking agents include: borates, divalent ionssuch as Ca²⁺, Mg²⁺, Fe²⁺, Zn²⁺ and salts thereof; trivalent ions such asAl³⁺, Fe³⁺ and salts thereof; metal atoms such as titanium or zirconiumin the +4 oxidation (valence) state. Crosslinking increases themolecular weight and is particularly desirable in high-temperature wellsto avoid decomposition, or other undesirable effects of high-temperatureapplications.

In an embodiment, the crosslinking agent is included in the fracturingfluid in an amount of from about 0.01 wt % to about 2.0 wt %,specifically about 0.02 wt % to about 1.0 wt % of the fracturing fluid,based on the total weight of the fracturing fluid.

In an embodiment, the crosslinked fracturing fluid has a viscosity ofabout 200 to about 3000 centipoise at 100 s⁻, specifically about 300 toabout 2500 centipoise at 100 s⁻¹, and more specifically about 300 toabout 1200 centipoise at 100 s⁻¹.

In an embodiment, the fracturing fluid further comprises a breakingagent to activate the labile group and facilitate decomposition of thepolymer. Breaking agents “break” or diminish the viscosity of thefracturing fluid so that the fracturing fluid is more easily recoveredfrom the formation during cleanup, e.g., using flowback. Breaking agentsinclude oxidizing agents (or oxidizers), reducing agents, enzymes, oracids. Breaking agents reduce the polymer's molecular weight by theaction of an acid, an oxidizer, an enzyme, or some combination of theseon the polymer itself. Non-limiting examples of breaking agents includepersulfates such as ammonium persulfate, sodium persulfate, potassiumpersulfate, bromates such as sodium bromate and potassium bromate,periodates, peroxides such as calcium peroxide, hydrogen peroxide,bleach, sodium perchlorate and organic percarboxylic acids or sodiumsalts, organic materials such as enzymes, or the like; chlorites, or thelike, or a combination comprising at least one of the foregoing breakingagents. Breaking agents can be introduced into the fracturing fluid inlive form or in encapsulated form.

In one embodiment, the breaking agent comprises an oxidizing agent and areducing agent. The oxidizing agent facilitates the decomposition of thepolymer with a consequent reduction in viscosity of the fracturingfluid. The reducing agent accelerates the decomposition rate of thepolymer beyond the rate facilitated by a breaking agent that comprisesonly an oxidizing agent. By varying the ratio of the oxidizing agent andthe reducing agent, the rate of decomposition of the polymer can becontrolled. In one embodiment, by varying the rate of addition of theoxidizing agent and/or the reducing agent to the hydrocarbon formationover time, the rate of decomposition of the polymer and the rate ofviscosity reduction of the fracturing fluid in the hydrocarbon formationmay be adjusted. The use of both an oxidizing agent and a reducing agentin a breaking agent thus permits greater control over the viscosityreduction characteristics of a fracturing fluid that contains only theoxidizing agent or the reducing agent. In this way, rapid and easyadjustments of the fluid viscosity of the synthetic polymer may be made.

The oxidizing agent promotes decomposition of the labile group of thesynthetic polymer. Examples of the oxidizing agent include any of theforegoing breaking agents, earth metal alkali oxidizing compounds,brominated or bromate oxidizing compounds such as sodium bromate, or acombination comprising at least one of the foregoing. In an embodiment,the oxidizing agent is effective to break or degrade the fracturingfluid at downhole or application temperatures greater than or equal toabout 275° F., specifically at temperatures of about 275° F. to about400° F. In an exemplary embodiment, the oxidizing agent is sodiumbromate.

In an embodiment, only the oxidizing agent is included in the fracturingfluid in an amount of from about 0.001 wt % to about 0.5 wt %,specifically from about 0.005 wt % to about 0.2 wt %, more specificallyfrom about 0.02 wt % to about 0.12 wt %, based on the total weight ofthe fracturing fluid.

In one embodiment, the fracturing fluid further comprises a reducingagent. As noted above, the reducing agent accelerates the rate ofdecomposition of the polymer thus bringing about a more rapid reductionin viscosity of the fracturing fluid. Examples of the reducing agentinclude sodium erythorbate, iron sulfate, oxalic acid, formic acid,ascorbic acid, erythorbic acid, a compound comprising a metal ionwherein the metal ion is a copper ion, an iron ion, a tin ion, amanganese ion or a sulfur ion such as thioglycol or a combinationcomprising at least one of the foregoing. In one embodiment, afracturing fluid that contains both an oxidizing agent and a reducingagent reduces the temperature of decomposition of the polymer to a muchlower temperature than that which would be accomplished by a fracturingfluid that contains either an oxidizing agent or a reducing agent.

In an embodiment, the reducing agent, in combination with the oxidizingagent, is effective to break, or degrade, the synthetic polymer in thefracturing fluid at downhole or application temperatures of less than orequal to about 275° F., specifically about 200° F. to about 275° F. Whenboth an oxidizing agent and a reducing agent are used in the fracturingfluid, the amount of the oxidizing agent is reduced relative to theamount of oxidizing agent used in a fracturing fluid that contains onlythe oxidizing agent and not the reducing agent.

When both the oxidizing agent and the reducing agent are present in thefracturing fluid, the oxidizing agent is included in the fracturingfluid in an amount of from about 0.001 wt % to about 0.5 wt %,specifically from about 0.005 wt % to about 0.2 wt %, more specificallyfrom about 0.02 wt % to about 0.12 wt %, based on the total weight ofthe fracturing fluid.

In an embodiment, the reducing agent is included in the fracturing fluidin an amount of from about 0.0006 wt % to about 0.12 wt %, specificallyabout 0.001 wt % to about 0.06 wt %, more specifically about 0.002 wt %to about 0.012 wt %, based on the total weight of the fracturing fluid.In another embodiment, the weight ratio of the oxidizing agent to thereducing agent is about 0.1:1 to about 100:1, specifically about 1:1 toabout 20:1, more specifically about 4:1 to about 12:1.

In an embodiment, the breaking agent is used to activate the controlleddecomposition of the polymer. In an embodiment, the breaking agent isadded to the fracturing fluid to instantly begin reducing the viscosityof the fracturing fluid. In another embodiment, the breaking agent isalready present in the fracturing fluid and is activated by someexternal or environmental condition. In an embodiment, an oilfieldbreaking agent is used to break the fracturing fluid using elevatedtemperatures downhole. For example, the breaking agent may be activatedat temperatures of 50° C. or greater.

In an embodiment, the fracturing fluid further comprises other additivesas desired and needed depending upon the particular conditions of thefracturing operation. Non-limiting examples of such additives include pHagents, buffers, mineral, oil, alcohol, biocides, clay stabilizers,surfactants, viscoelastic surfactants, emulsifiers, non-emulsifiers,scale-inhibitors, fibers, fluid loss control agents and combinationscomprising at least one of the foregoing additives.

In an exemplary embodiment, the fracturing fluid further may compriseother additives as desired for a particular application. Examples ofsuch additives include, but are not limited to, any of the foregoingadditives, clay control agents, one or more of the foregoingcrosslinking agents, buffers, and breaker catalysts.

A clay control agent is used to control and prevent clay swelling.Examples of clay control agents include ammonium chloride, tetramethylammonium chloride and diallyl dimethyl ammonium chloride.

In an embodiment, the clay control agent is included in the fracturingfluid in an amount of from about 0.01 wt % to about 2 wt %, specificallyabout 0.02 wt % to about 1 wt %, more specifically about 0.05 wt % toabout 0.1 wt %, based on the total weight of the fracturing fluid.

A breaker catalyst is used to catalyze, or activate, the breaking oroxidizing agent. An example of a breaker catalyst is acetyl triethylcitrate.

In an embodiment, the breaker catalyst is included in the fracturingfluid in an amount of from about 0.0011 wt % to about 1.1 wt %,specifically about 0.011 wt % to about 0.55 wt %, more specificallyabout 0.022 wt % to about 0.22 wt %, based on the total weight of thefracturing fluid.

A buffer is used to maintain the pH of the fracturing fluid. Examples ofbuffers include formic acid and acetic acid.

In an embodiment, the buffer is included in the fracturing fluid in anamount of from about 0.001 wt % to about 1 wt %, specifically about 0.01wt % to about 0.5 wt %, more specifically about 0.05 wt % to about 0.2wt %, based on the total weight of the fracturing fluid.

In one embodiment, in one method of manufacturing the fracturing fluid,the polymer is dissolved into the carrier fluid in an amount effectiveto increase the viscosity of the carrier fluid. Other additives such asthe proppant, surfactants, breaking agents, and the like, may be presentin the carrier fluid either prior to the addition of the polymer or maybe added to the carrier fluid after the addition of the polymer. Thepolymer rapidly dissolves into the carrier fluid increasing itsviscosity. The increase in viscosity indirectly reduces friction betweencomponents of the fracturing equipment and reduces settling of theproppants in the carrier fluid as the fracturing fluid travels to thefracture in the subterranean zone.

In an embodiment, the viscosity of the carrier fluid is increased byabout 100% to about 900% in about 10 to about 100 seconds uponintroduction of the polymer to the carrier fluid. In another embodiment,the viscosity of the carrier fluid is increased by about 500% to about800% in about 20 to about 90 seconds upon introduction of the polymer tothe carrier fluid. In yet another embodiment, the viscosity of thecarrier fluid is increased by about 550% to about 750% in about 70 toabout 100 seconds upon introduction of the polymer to the carrier fluid.

In an embodiment, the fracturing fluid, in an uncrosslinked state orprior to crosslinking, has a viscosity of about 5 to about 50centipoise, specifically about 6 to about 30 centipoise, and morespecifically about 7 to about 20 centipoise, upon introduction of thepolymer to the carrier fluid. In another embodiment, the viscosity ofthe carrier fluid begins increasing upon introduction of the syntheticpolymer to the carrier fluid. Although not wishing to be bound bytheory, it is thought that the polymer increases the viscosity of thecarrier fluid due to not only the molecular weight and structure of thepolymer itself but also due to the formation of a network of physicalbonds (e.g., hydrogen bonds or ionic bonds) between the polymers,resulting in a gel-like fluid, without crosslinking.

In one method of using the fracturing fluid, the polymer is added to thecarrier fluid and undergoes rapid dissolution upon contacting thecarrier fluid. The fracturing fluid is pumped downhole almost as soon asthe polymer is introduced into the carrier fluid. Because the polymerundergoes rapid hydration upon introduction into the carrier fluid, thefracturing fluid is immediately pumped downhole. The rapid hydration ofthe polymer by the carrier fluid promotes an increase in the viscosityof the fracturing fluid as it is pumped thereby reducing frictionbetween the various mechanical components (e.g., components of thedrilling and fracturing equipment) as it travels downhole. As thefracturing fluid travels downhole, the increase in viscosity of thefracturing fluid allows the fracturing fluid to be pumped at a lowerrate without significant settling of the proppants.

The fracturing fluid generally reaches its maximum viscosity when itpenetrates the fracture. Once in the fracture, the proppants present inthe fracturing fluid are disposed in the fracture and are used to propopen the fracture. When the fracture is supported by the proppants, thelabile groups in the fracturing fluid are activated to decompose thepolymer in the fracturing fluid. The breaking agent comprising theoxidizing agent and the reducing agent facilitate the decomposition ofthe polymer. In one embodiment the oxidizing agent and the reducingagent are simultaneously added to the fracturing fluid after the polymerhas crosslinked. In another embodiment, the oxidizing agent is firstadded to the fracturing fluid followed by the reducing agent. In yetanother embodiment, the oxidizing agent and the reducing agent are addedsequentially in an alternating fashion to facilitate decompositioncontrol and viscosity control. In still yet another embodiment, thecrosslinking agent and the oxidizing agent and/or reducing agent areadded sequentially in an alternating fashion to facilitate crosslinkingcontrol and decomposition and viscosity control. The decomposition ofthe fracturing fluid causes a reduction in its viscosity, which permitsits removal from the fracture. The removal of the fracturing fluid fromthe fracture leaves behind a conductive path way in the proppantsthrough which hydrocarbons may be removed from the fracture.

The polymer used in the fracturing fluid has a number of advantages overother commercially available polymers that are presently used infracturing fluids. Since the polymer is synthetic (i.e., man-made) isnot subject to some of the production constraints of naturally occurringpolymers. It undergoes rapid dissolution when mixed with the carrierfluid. It exhibits a maximum viscosity at ambient temperature of equalto or greater than about 8 centipoise after about 30 seconds followingthe introduction of the polymer into the carrier fluid. The ability ofthe polymer to rapidly dissolve in the carrier fluid causes thefracturing fluid to reach about 85% or greater of the maximum viscosityat about 45° F. after about 15 seconds.

In another embodiment, the fracturing fluid comprises a breaking agent,which will break the polymer chains and significantly reduce the fluidviscosity to less than 10 centipoise at temperature equal to or above100° F.

In another embodiment, in one method for treating a hydrocarbon-bearingformation the carrier fluid is blended with a synthetic polymer to forma fracturing fluid, where the fracturing fluid has a viscosity of about5 to about 50 centipoise. Following the blending, the fracturing fluidis discharged into a downhole fracture in the hydrocarbon-bearingformation. The fracturing fluid acts to reduce friction betweencomponents of the drilling and fracturing equipment during ahydrocarbon-bearing treatment operation. In an embodiment, the carrierfluid is discharged into the hydrocarbon-bearing formation, i.e.,downhole, and the synthetic polymer and optional additives areintroduced into the carrier fluid downhole.

The invention is further described by the following non-limitingexamples.

EXAMPLES Example 1

This example was conducted to show the rapid hydration of the polymerwhen compared with guar which is a commercially available naturallyoccurring polymer. In this example, hydraulic fracturing fluidscomprising the synthetic polymer disclosed herein were compared withhydraulic fracturing fluids that use guar (a naturally occurringpolymer). The polymer is a synthetic polymer and comprises apolyacrylamide. It is commercially available as MaxPerm-20® from BakerHughes, Incorporated. The carrier fluid is water.

For this example, the synthetic polymer MaxPerm-20® was dissolved inwater as shown in the Table 1 and viscosity measurements were made. Theviscosity measurements were made at ambient temperature using an Ofiterheometer at 300 revolutions per minute (rpm) and performed according toAmerican Petroleum Institute standard API RP-39. The viscosity resultsare provided in the Table 1 and in the FIG. 1. The comparative samplescontain guar dissolved in water. These results are also provided in theTable 1 and in the FIG. 1. The FIG. 1 is a graph of viscosity (incentipoise) measured at 300 rpm versus time (in minutes) for therespective samples.

In the Table 1, Samples 1 and 2 are comparative examples that contain2.5 gpt (gallons per thousand) and 3.75 gpt guar slurry respectively.Samples 3, 4 and 5 are examples that display the viscosity properties ofsamples that contain 2, 3 and 4 gpt respectively of the syntheticpolymer MaxPerm-20®. From Table 1 and FIG. 1 it may be seen that thesynthetic polymer reaches a maximum viscosity at lower loading levelsthan the guar.

TABLE 1 Hydration time to Sample # Composition Viscosity (cP) maximumviscosity  1* 2.5 gpt guar (10 ppt 4.7 ~8.25 minutes guar)  2* 3.75 gpt(15 ppt guar) 8.2 10 minutes 3 2 gpt MaxPerm-20 5.3 Less than 30 seconds4 3 gpt MaxPerm-20 9 Less than 30 seconds 5 4 gpt MaxPerm-20 11 Lessthan 30 seconds *Comparative Examples

For example, in comparing Sample #2 with Sample #4, it may be seen thata concentration of 3.75 gpt of guar (in water) produces a maximumviscosity of 8.2 centipoise, while 3 gpt of the synthetic polymer (inwater) produces a maximum viscosity of 9 centipoise. In addition, it maybe seen that while the guar takes about 8 to 10 minutes to undergohydration, the synthetic polymer undergoes hydration in less than 30seconds. Thus, fracturing fluids using the synthetic polymer describedherein demonstrate a much more rapid hydration in much less time thanthe guar-based comparative fracturing fluid.

Example 2

This example was conducted to demonstrate the dynamic hydrationproperties of the synthetic polymer. This polymer used in this exampleis the synthetic polymer MaxPerm-20®. The carrier fluid was water.

In this example, the viscosity was measured upon the introduction ofdifferent amounts of the synthetic polymer to the water. The viscositythus measured during the hydration of the synthetic polymer by water.The resulting viscosity is therefore a measure of dynamic hydration ofthe synthetic polymer by water. The polymer was dissolved in the waterat 45° F. (7.2° C.) and 80° F. (26.6° C.), during which the viscositywas measured. The results are shown in the FIG. 2. The FIG. 2 is a graphdepicting the dynamic hydration viscosity at temperatures of 45° F. and80° F. versus time for the synthetic polymer in water. The concentrationof the polymer in the water at each of the foregoing temperatures was0.75 gpt, 1 gpt, 2 gpt or 3 gpt respectively.

From the FIG. 2 it may be seen that synthetic polymer hydrates rapidlyin the water in a time period of less than 200 seconds irrespective ofthe temperature or the concentration. For each concentration, thefracturing fluid reaches a 85% of the maximum viscosity attainablewithin about 40 seconds of the introduction of the synthetic polymerinto the water.

Example 3

This example was conducted to evaluate possible formation damage fromthe use of the synthetic polymer in a fracturing fluid and to compare itwith the damage caused by the use of guar in a comparative fracturingfluid. In this example, the permeability of a simulated fracture surfacecomprising 81% quartz, 2% K-feldspar, and 11% MILIS is first measured.The simulated fracture surface is then contacted with the respectivefracturing fluid (i.e., a fracturing fluid comprising the syntheticpolymer MaxPerm-20® or a comparative fracturing fluid comprising linearguar). The fracturing fluid was then oxidized, decomposed and removedfrom the simulated fracture surface following which the permeability ofthe simulated fracture surface is once again measured. The differencebetween the initial permeability and the final permeability is a measureof the formation damage that the polymer imparts to the fracturesurface. The gas used to check the permeability is nitrogen. It isgenerally desirable for this damage to be as little as possible. Inshort, it is desirable that the initial permeability of the simulatedfracture surface be almost the same values as the permeability of thesimulated fracture surface after the fracturing fluid is removed fromcontact with the simulated fracture surface.

In this example, the synthetic polymer (MaxPerm-20®) and the comparativepolymer (guar) were each separately dissolved in a carrier fluid to formthe fracturing fluid. Added to these fracturing fluids is an oxidizer tobreak down the fracturing fluid after it contacts the simulated fracturesurface. The respective fracturing fluids contact the simulated fracturesurface at 180° F. (82.22° C.) under an injection pressure of 60 psi(pounds per square inch) (4.2 kilograms per square centimeter (kg/cm²))and a confining pressure of 1,500 psi (105.46 kg/cm²) for period of 20hours. After the confining period of 20 hours, the oxidizer wasactivated to decompose the respective polymers and the fracturing fluidwas removed from contact with the simulated fracture surface. Thepermeability of the simulated fracture surface was measured before andafter contact with the respective fracturing fluids and the results areshown in the FIGS. 3 and 4 for the fracturing fluid containing thesynthetic polymer and the guar respectively.

FIG. 3 shows the permeability for the fracturing fluid containing thesynthetic polymer disclosed herein, i.e., the MaxPerm-20®. From the FIG.3, it may be seen that the permeability regained after removal of thefracturing fluid is 92%. FIG. 4 shows the permeability for thefracturing fluid containing the linear guar. From the FIG. 4, it may beseen that the permeability regained after removal of the fracturingfluid is 78.3%.

In comparing the FIGS. 3 and 4, it may be seen that there issubstantially less residue left in the simulated fracture surface usingthe MaxPerm-20® especially when compared with the guar. The syntheticpolymer can thus be used to produce a fracturing fluid that producesfewer detrimental effects on fracture surfaces than other naturallyoccurring polymers such as guar.

From the results seen in the Examples 1, 2 and 3, it may be seen thatthe synthetic polymer disclosed herein can rapidly dissolve in anaqueous carrier fluid after breaking, and produces less formation damagethan other polymers such as, for example guar. The fracturing fluidsthat contain the synthetic polymer therefore provide an effective andeconomical alternative to guar-based fracturing fluids, demonstrate fasthydration with almost an instantaneous increase in viscosity followinghydration, allows for rapid and easy adjustments of fluid viscosity andfor switching the polymers used to produce the viscosity increasingadditive, protect well fracturing equipment and leave little to noformation damage upon being activated and decomposed with a commerciallyavailable oilfield breaking agent.

Example 4

This example was conducted to show the apparent viscosity versus timeand temperature for a fracturing fluid that contains the syntheticpolymer, a crosslinking agent and an oxidizing agent. In this example,the apparent viscosity in centipoises (cP) of the fracturing fluid wasmeasured versus time and temperature. The polymer is the MaxPerm-20®synthetic polymer and comprises a polyacrylamide. The carrier fluid iswater. The crosslinker is zirconium methyl n-glycinate and zirconiumacetyl acetonate. The oxidizing agent is sodium bromate, a commerciallyavailable oilfield breaking agent.

For this example, 10 gallons per thousand gallons (gpt) of theMaxPerm-20® synthetic polymer was dissolved in a water carrier fluid toform the fracturing fluid. The synthetic polymer was allowed to hydratein the carrier fluid for about 30 minutes. 5 pounds per thousand (ppt)of a sodium bromate oxidizing agent was added to the fracturing fluid.The apparent viscosity at 100 revolutions per minute (rpm) was measuredat a temperature of 225° F. (107.22° C.) using a Chandler viscometer(Model No. 5550) with a RIBS bob and cup configuration against time inminutes according to API RP-39, Section 4.2.6. The viscosity results areprovided in FIG. 5. FIG. 5 is a graph of the viscosity (in centipoise)measured at 100 s⁻¹ versus time (in minutes) at a temperature of 225° F.

From FIG. 5, it may be seen that introduction of the sodium bromateoxidizing agent incompletely breaks or decomposes the synthetic polymerin the fracturing fluid. For example, the apparent viscosity of thefracturing fluid is about 800 cP at about 20 minutes. The apparentviscosity decreases to about 700 cP at about 30 minutes. At about 100minutes, the apparent viscosity increases to about 740 cP and exhibits astable viscosity. The fracturing fluid containing the synthetic polymerdemonstrates only partial or incomplete breaking demonstrating areduction in viscosity of only about 60 cP over time at a temperature ofabout 225° F. Thus, the sodium bromate oxidizing agent exhibits a lowdecomposition potential for the crosslinked synthetic polymer at atemperature of about 225° F.

Example 5

This example was conducted to show the apparent viscosity versus timeand temperature for a fracturing fluid that contains the syntheticpolymer, an oxidizing agent and a reducing agent. The reducing agent isiron sulfate. The fracturing fluid contained about 10 gpt of thesynthetic polymer, about 1.5 ppt sodium bromate and 0.5 ppt ironsulfate. The crosslinker is zirconium methyl n-glycinate and zirconiumacetyl acetonate. The carrier fluid is water. The apparent viscosity incentipoises (cP) of the fracturing fluid was measured versus time andtemperature according to Example 4. These results are provided in FIG.6. FIG. 6 is a graph of the viscosity (in centipoise) measured at 100revolutions per minute (rpm) versus time (in minutes) at a temperatureof 225° F. for the fracturing fluid of Example 5.

From FIG. 6 it may be seen that the addition of the iron sulfatereducing agent to a fracturing fluid that contains the syntheticpolymer, water carrier fluid and sodium bromate oxidizing agent resultsin increased decomposition, or more complete breaking, of the syntheticpolymer in the fracturing fluid in comparison to the fracturing fluid ofExample 4. The fracturing fluid demonstrates a reduction in viscosityfrom about 240 cP to about 210 cP after about 30 minutes, and rapidlydecreases thereafter to about 70 cP at about 3 hours. Thus, thefracturing fluid containing the synthetic polymer, the water carrierfluid, the sodium bromate oxidizing agent and the iron sulfate oxidizingagent exhibits a higher oxidation potential for the crosslinkedsynthetic polymer at a temperature of about 225° F. in comparison to thefracturing fluid of Example 4.

In addition, when Example 5 is compared with Example 4, it may be seenthat the amount of sodium bromate oxidizing agent used to facilitatecomplete breaking of the fracturing fluid is significantly less thanthat used to achieve the incomplete breaking demonstrated in Example 4,from 5 ppt to about 1.5 ppt, while a small amount, 0.5 ppt, of ironsulfate was added in Example 5.

Example 6

This example was conducted to show the apparent viscosity versus timeand temperature for fracturing fluids that contain the syntheticpolymer, the carrier fluid, the oxidizing agent and the reducing agentas well as a breaker catalyst, a clay control agent, a buffer andcrosslinking agents. The polymer used in this example is the MaxPerm-20®synthetic polymer. The carrier fluid is water. The oxidizing agent issodium bromate. The reducing agent is iron sulfate. The buffer is aceticacid. The clay control agent is tetramethyl ammonium chloride. Thecrosslinking agents are zirconium methyl n-glycinate and zirconiumacetyl acetonate. The breaker catalyst is acetyl triethyl citrate. Therespective samples contain different amounts of the sodium bromatereducing agent, as shown in Table 2. Each sample contained 10 gptMaxPerm-20; 0.3 gpt acetic acid; 1 gpt tetramethyl ammonium chloride; 1gpt zirconium methyl n-glycinate, 2 ppt zirconium zirconium acetylacetonate; 1 gpt acetyl triethyl citrate and 0.5 ppt iron (II) sulfate.The pH of each of the fracturing fluid samples 6-9 was 5.40, 5.55, 5.60and 5.30, respectively.

The apparent viscosity in centipoises (cP) of the fracturing fluid wasmeasured versus time and temperature according to Example 4. Theseresults are provided in Table 2 and FIG. 7. FIG. 7 is a graph of theviscosity (in centipoise) measured at 100 revolutions per minute (rpm)versus time (in minutes) at a temperature of 225° F. for the respectivesamples.

In Table 2, Samples 6-9 contain 2.0 ppt, 4.0 ppt, 5.0 ppt and 6.0 ppt ofthe sodium bromate oxidizing agent, respectively. Each of samples 6-9also contains 0.5 ppt of the iron sulfate reducing agent. From Table 2and FIG. 7, it may be seen that the rate of oxidation may be controlledby varying the amount of the oxidizing agent used in combination withthe reducing agent in the fracturing fluid.

TABLE 2 Viscosity Viscosity Viscosity Viscosity Viscosity Oxidizing (cP)(cP) (cP) (cP) (cP) Sample # Agent at 0 hr at 1 hr at 2 hr at 4 hr at 6hr 6 2.0 ppt sodium 250 310 250 120 60 bromate 7 4.0 ppt sodium 250 250200 100 50 bromate 8 5.0 ppt sodium 250 190 100 25 1 bromate 9 6.0 pptsodium 250 75 40 10 1 bromate

For example, in comparing Sample #6 with Sample #7, it may be seen thata concentration of 2.0 ppt of the sodium bromate oxidizing agent incombination with 0.5 ppt of the iron sulfate reducing agent results inan increase in viscosity of from 250 cP to 310 cP after one hour, while4.0 ppt of the sodium bromate oxidizing agent in combination with 0.5ppt of the iron sulfate reducing agent results in a viscosity of about250 cP after one hour. As shown in FIG. 7, while Sample #6 and #7 bothdemonstrate an initial increase in viscosity, Sample #7 demonstrates asignificantly reduced initial increase in viscosity in comparison toSample #6. Sample #7 also demonstrates a significantly reduced durationof time before the viscosity begins to decrease, with the decomposition,or breaking, of the synthetic polymer being exhibited after about 30minutes for Sample #7 in comparison to over one hour for Sample #6.

In addition, it may be seen that Sample #8, containing 5 ppt of theoxidizing agent, in combination with the reducing agent, demonstratesthe breaking or decomposition of the synthetic polymer in the fracturingfluid without an initial increase in viscosity. Furthermore, incomparing Sample #8 with Sample #9, it may be seen that a concentrationof 6.0 ppt of the oxidizing agent, in combination with the reducingagent, demonstrates the breaking or decomposition of the syntheticpolymer in the fracturing fluid almost immediately and without aninitial increase in viscosity. Thus, the rate of oxidation may becontrolled by selecting the particular amounts of oxidizing agent andreducing agent used in combination with the synthetic polymer in thefracturing fluid.

From the results seen in Examples 4-6, it may be seen that the additionof a relatively small amount of a reducing agent to the oxidizing agentwill facilitate the complete breaking or decomposition of the syntheticpolymer in the fracturing fluid at lower application temperatures.Fracturing fluids that contain the reducing agent, in addition to thesynthetic polymer and the oxidizing agent, therefore demonstrate thatcomplete or nearly complete breaking, or decomposition of the syntheticpolymer can be achieved with a commercially available oilfield oxidizingagent and allow for control of and rapid and easy adjustments to theoxidation rate of the synthetic polymer and the fluid viscosity of thefracturing fluid throughout the period of decomposition.

The fracturing fluid may be used in a stimulation treatment, afracturing treatment, an acidizing treatment, a friction reducingoperation or a downhole completion operation. The fracturing fluid canbe used as a gel or a slurry or a combination of at least one of theforegoing.

This invention may be embodied in many different forms, and should notbe construed as limited to the embodiments set forth herein. Rather,these embodiments are provided so that this disclosure will be thoroughand complete, and will fully convey the scope of the invention to thoseskilled in the art. Like reference numerals refer to like elementsthroughout.

The terminology used herein is for the purpose of describing particularembodiments only and is not intended to be limiting. As used herein, thesingular forms “a,” “an” and “the” are intended to include the pluralforms as well, unless the context clearly indicates otherwise. It willbe further understood that the terms “comprises” and/or “comprising,” or“includes” and/or “including” when used in this specification, specifythe presence of stated features, regions, integers, steps, operations,elements, and/or components, but do not preclude the presence oraddition of one or more other features, regions, integers, steps,operations, elements, components, and/or groups thereof.

As used herein, the term “fracturing operation” shall include astimulation treatment, a fracturing treatment, an acidizing treatment, afriction reducing operation or a completion operation, downhole, or thelike.

Unless otherwise defined, all terms (including technical and scientificterms) used herein have the same meaning as commonly understood by oneof ordinary skill in the art to which this disclosure belongs. It willbe further understood that terms, such as those defined in commonly useddictionaries, should be interpreted as having a meaning that isconsistent with their meaning in the context of the relevant art and thepresent disclosure, and will not be interpreted in an idealized oroverly formal sense unless expressly so defined herein.

The transition term “comprising” is inclusive of the transition terms“consisting of” and “consisting essentially of”.

All numerical ranges included herein are interchangeable and areinclusive of end points and all numerical values that lie between theendpoints.

As used herein a “borehole” may be any type of well, including, but notlimited to, a producing well, a non-producing well, an experimentalwell, an exploratory well, a well for storage or sequestration, and thelike. Boreholes may be vertical, horizontal, some angle between verticaland horizontal, diverted or non-diverted, and combinations thereof, forexample a vertical borehole with a non-vertical component.

The terms “decompose”, “decomposition” and/or “degradable” refer to theconversion of materials into smaller components, intermediates, or endproducts.

The term and/or is used herein to mean both “and” as well as “or”. Forexample, “A and/or B” is construed to mean A, B or A and B.

As used herein, the term “treatment” or “treating” refers to anyhydrocarbon-bearing formation operation that uses a fluid in conjunctionwith a desired function or purpose. The term “treatment” or “treating”does not imply any particular action by the fluid or any particularconstituent thereof.

While the invention has been described in detail in connection with anumber of embodiments, the invention is not limited to such disclosedembodiments. Rather, the invention can be modified to incorporate anynumber of variations, alterations, substitutions or equivalentarrangements not heretofore described, but which are commensurate withthe scope of the invention. Additionally, while various embodiments ofthe invention have been described, it is to be understood that aspectsof the invention may include only some of the described embodiments.Accordingly, the invention is not to be seen as limited by the foregoingdescription, but is only limited by the scope of the appended claims.

What is claimed is:
 1. A method for treating a hydrocarbon-bearingformation comprising: blending a carrier fluid with a synthetic polymerand an oxidizing agent to form a fracturing fluid, the synthetic polymerbeing a polyacrylamide further comprising a labile group or apolyacrylate further comprising a labile group, the labile groupcomprising ester groups, carbonate groups, azo groups, disulfide groups,orthoester groups, acetal groups, etherester groups, ether groups, silylgroups, phosphazine groups, urethane groups, etheramide groups,anhydride groups, or a combination thereof; the oxidizing agent and thelabile group being selected such that the oxidizing agent is effectiveto activate the labile group and the activated labile group facilitatesthe decomposition of the synthetic polymer; injecting the fracturingfluid into the hydrocarbon-bearing formation, the fracturing fluidhaving a viscosity of about 5 to about 50 centipoise during injection;discharging the fracturing fluid into a downhole fracture in thehydrocarbon-bearing formation, wherein the fracturing fluid is operativeto reduce friction during a hydrocarbon-bearing treatment operation;activating the labile group on the synthetic polymer with the oxidizingagent; decomposing the synthetic polymer upon activation of the labilegroup to provide a decomposed polymer; and removing the decomposedpolymer from the hydrocarbon-bearing formation, wherein the syntheticpolymer is devoid of guar.
 2. The method of claim 1, further comprisingadding a reducing agent to the fracturing fluid.
 3. The method of claim2, wherein the reducing agent is sodium erythorbate, iron sulfate,oxalic acid, formic acid, ascorbic acid, erythorbic acid, a compoundcomprising a metal ion wherein the metal ion is a copper ion, an ironion, a tin ion, a manganese ion or a sulfur ion, or a combinationcomprising at least one of the foregoing.
 4. The method of claim 2,wherein the weight ratio of the oxidizing agent to the reducing agent isabout 0.1:1 to about 100:1.
 5. The method of claim 2, wherein theoxidizing agent is present in an amount from about 0.001 wt % to about0.5 wt %, based on the total weight of the fracturing fluid, and thereducing agent is present in an amount from about 0.0006 wt % to about0.12 wt %, based on the total weight of the fracturing fluid.
 6. Themethod of claim 2, wherein the oxidizing agent is present in an amountof about 0.02 wt. % to about 0.12 wt. %, the reducing agent is presentin an amount of about 0.002 wt. % to about 0.012 wt. %, each based onthe total weight of the fracturing fluid; and the weight ratio of theoxidizing agent to the reducing agent is about 1:1 to about 20:1.
 7. Themethod of claim 2, wherein the reducing agent is iron sulfate.
 8. Themethod of claim 1, further comprising adding a crosslinking agent to thefracturing fluid.
 9. The method of claim 1, wherein the oxidizing agentis an earth metal alkali oxidizing compound, a bromate oxidizingcompound, or a combination comprising at least one of the foregoing. 10.The method of claim 1, wherein the synthetic polymer is thepolyacrylamide further comprising the labile group.
 11. The method ofclaim 1, wherein upon activation of the labile group, the viscosity ofthe fracturing fluid is reduced to 2 centipoise or less.
 12. The methodof claim 1, wherein the fracturing fluid is free of a crosslinkingagent.
 13. The method of claim 1, wherein the fracturing fluid is freeof a naturally occurring polymer.
 14. The method of claim 1, wherein thesynthetic polymer has a number average molecular weight of about2,000,000 to about 20,000,000 grams per mole.
 15. The method of claim 1,wherein the synthetic polymer is present in an amount of about 0.1 wt %to about 10 wt %, based on the total weight of the fracturing fluid. 16.The method of claim 1, wherein the fracturing fluid further comprises aclay control agent or a breaker catalyst.
 17. The method of claim 1,wherein the oxidizing agent is sodium bromate, potassium bromate, or acombination comprising at least one of the foregoing.
 18. The method ofclaim 1, wherein the fracturing fluid further comprises acetyl triethylcitrate.
 19. The method of claim 18, wherein the acetyl triethyl citrateis included in the fracturing fluid in an amount of from about 0.0011 wt% to about 1.1 wt %, based on the total weight of the fracturing fluid.20. A method for treating a hydrocarbon-bearing formation comprising:blending a carrier fluid with a synthetic polymer, an oxidizing agent,and a reducing agent to form a fracturing fluid, the synthetic polymerbeing a polyacrylamide copolymer further comprising a labile group or apolyacrylate copolymer further comprising a labile group, the labilegroup comprising ester groups, amide groups, carbonate groups, azogroups, disulfide groups, orthoester groups, acetal groups, etherestergroups, ether groups, silyl groups, phosphazine groups, urethane groups,etheramide groups, anhydride groups, or a combination thereof; theoxidizing agent and the labile group being selected such that theoxidizing agent is effective to activate the labile group and theactivated labile group facilitates the decomposition of the syntheticpolymer; injecting the fracturing fluid into the hydrocarbon-bearingformation, the fracturing fluid having a viscosity of about 5 to about50 centipoise during injection; discharging the fracturing fluid into adownhole fracture in the hydrocarbon-bearing formation, wherein thefracturing fluid is operative to reduce friction during ahydrocarbon-bearing treatment operation; activating the labile group onthe synthetic polymer with the oxidizing agent; wherein upon activationof the labile group, the viscosity of the fracturing fluid is reduced to2 centipoise or less; decomposing the synthetic polymer upon activationof the labile group to provide a decomposed polymer; and removing thedecomposed polymer from the hydrocarbon-bearing formation, wherein thesynthetic polymer is present in an amount of about 0.1 wt. % to about 10wt. %, the oxidizing agent is present in an amount of about 0.02 wt. %to about 0.12 wt. %, and the reducing agent is present in an amount ofabout 0.002 wt. % to about 0.012 wt. %, each based on the total weightof the fracturing fluid; and the weight ratio of the oxidizing agent tothe reducing agent is about 4:1 to about 12:1.
 21. The method of claim20, wherein the carrier fluid is slickwater.
 22. The method of claim 20,wherein the fracturing fluid further comprises acetyl triethyl citratein an amount of from about 0.011 wt % to about 0.55 wt %, based on thetotal weight of the fracturing fluid.
 23. The method of claim 20,wherein the fracturing fluid reaches its maximum viscosity within 10 to40 seconds after introduction of the synthetic polymer into the carrierfluid.